The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.
The present disclosure relates generally to wellbore treatment and development of a reservoir and, in particular, to a system and a method for determining characteristics of a tubing disposed in a wellbore.
In all stages of well construction for oil and gas extraction from a subterranean reservoir, including drilling, logging, completion and workover operations, a means of conveyance (i.e. tubing) is required to lower a tool, or tools, into the well to facilitate these operations. The tools may include a drilling bit, a logging tool, a packer, a downhole completion string such as a liner or a screen, a perforating gun, a jetting tool, and the like. The means of conveyance (i.e. tubing) can be a jointed pipe, a continuous pipe such as a coiled tubing (CT), or a slickline or wireline cable.
As the tubing moves into a well, the tubing is subjected to increasing forces along its length, as a result of a weight of the tubing itself, a buoyancy force of a fluid in the wellbore, a contact friction with the wall of the wellbore, a pressure inside the wellbore, and a load applied at the bottom of the tool being conveyed (also called weight on bit). Excessive force in tension or compression can cause the failure of the tubing or the tools coupled to the tubing, resulting in a failed operation, an expensive loss of production, or even a loss of the entire well.
To better plan, execute, and optimize the wellbore operations, mathematical models have been developed for computing the torque and drag forces in the drill pipe during drilling operations, especially for deviated and horizontal well drilling, as described in a paper by Johncsik et al. entitled “Torque and Drag in Directional Wells—Prediction and Measurement” and incorporated herein by reference in its entirety. (See Johncsik, C. A., Friesen, D. B., and Dawson, R., “Torque and Drag in Directional Wells—Prediction and Measurement,” IADC/SPE Paper 11380, IADC/SPE Drilling Conference, New Orleans, Feb. 20-23, 1983).
Torque and drag models developed for drilling are also extended to applications using coiled tubing and cable. Unlike conventional jointed pipes, coiled tubing cannot stand substantial compression force and may be susceptible to buckling failure. Therefore, a plurality of Tubing Forces Models (TFM) for coiled tubing have been developed by incorporating buckling models, as described in a paper by Chen et al. entitled “An Analysis of Tubing and Casing Buckling in Horizontal Wells” and incorporated herein by reference in its entirety. (See Chen, Y. C., Lin, Y. H., and Cheatham, A. B., “An Analysis of Tubing and Casing Buckling in Horizontal Wells,” OTC paper 6037, Offshore Technology Conference, May 1989).
Conventional TFMs are used extensively in various planning and job design processes and has been shown to predict the tubing force reasonably accurately when certain well parameters are known, as described in a paper by Van Adrichem et al. entitled “Validation of Coiled Tubing Penetration Predictions in Horizontal Wells” and incorporated herein by reference in its entirety. (See Van Adrichem, W. and Newman, K. R., “Validation of Coiled Tubing Penetration Predictions in Horizontal Wells,” SPE paper 24765, SPE 67th Annual Technical Conference and Exhibition, Washington D.C., Oct. 4-7, 1992).
TFMs play a critical role in planning a well operation in an extended reach well to let the operator know beforehand whether a given tubing string can successfully reach a target depth without problem, and whether other means to extend the reach, such as friction reducers or mechanical tractors, is required.
For example, U.S. Pat. No. 6,433,242 discloses a method of running a TFM multiple times prior to a job to generate a simple (curve fitted) model for use during a job to be able to quickly match the measured surface CT weight. However, without integrating real-time downhole measurements, such exercise may lead to incorrect parameters that produce wrong calculations.
As a further example, U.S. Pat. Appl. Pub. No. 2008/0308272 discloses a general methodology of using downhole pressure, temperature, load, velocity and other measurements to provide continuous real-time closed loop interpretations to sense various types of downhole events.
However, some of the key parameters that affect tubing forces are not known accurately, which include the contact friction between the coiled tubing and the wellbore wall, the inherently unknown helical shape of the pipe due to the residual bending of the coiled tubing, and unknown tool contact force at the well bottom in drilling, milling or jetting operations. Other key parameters, such as a CT stripper force, a reel back tension, a fluid density, and a pressure, change constantly during the well operations, which also cause significant variations in tubing forces. Due to these reasons, the surface weight indicator as predicted by a TFM (based on the assumed parameters) sometimes does not match the actual measured CT weight. The mismatch could lead to undesired failures since the TFM is no longer providing the correct tubing forces calculation. Alternatively, the operator could adjust the input parameters to match the measured surface weight, but this process is non-unique since several factors can affect the measured weight as stated above. Incorrect assumptions of the parameters would again lead to errors in calculation.
In operations such as fill cleanout using coiled tubing, the fill materials can pile up in the wellbore, leading to increased apparent CT/wall friction. If the apparent friction can be estimated, it can be a good indicator for potential problems when too much fill materials are accumulated in the well, leading to a potential stuck pipe situation. Other operations include interventions in a deviated/horizontal open hole section, where a potentially collapsed bore hole could lead to additional CT/wall friction. Understanding when such friction increases will also prevent a stuck pipe situation.
Excessive forces on the CT, either tensile or compression, may cause the pipe to break or buckle. When a CT is running in a long horizontal well, the gravity force causes the CT to lie on the bottom of the wellbore. The contact friction between CT and wellbore leads to increased force building up along the part of the CT lying in the horizontal section of the well. If the CT is running in the hole, a compression force builds up. If it exceeds a critical value, the CT undergoes helical buckling, leading to CT lock up in the well.
In order to accurately predict tubing forces during a well operation, simulated models (e.g. TFM) must use additional downhole measurements to reduce the uncertainty of the parameters, including measured downhole pressure and force at the bottom, and potentially other parameters.
This disclosure describes a method of using the real-time measurements to calibrate the TFM parameters and use the calibrated parameters to predict tubing forces more accurately and to overcome the shortcomings of the prior art.